Knowledge of the individual flow rates of the gas fraction, the oil fraction, and the water fraction within the flow of fluid from an oil well is an important part of the efficient management of the well and the associated subsurface reservoir. Such wells typically tap into reservoirs such as that shown in FIG. 1, in which a simplified well is shown penetrating a reservoir. The reservoir consists of a permeable rock formation typically filled with a lower layer of water 110, an intermediate layer of oil 112, and an upper layer of gas 114 trapped under a layer of cap rock 116. The result of this is that the balance between the fractions of each that are extracted is affected by the positioning of the well perforations 120 at the lower end of the production string 122 relative to the layers, and the flow rate of the fluid out of the well. The flow rate is relevant in that over production of a well can reduce the total amount of oil recovered due to a number of reasons, including drawing the underlying water layer 124 up towards the perforations 120 and creating a cone of water above the undisturbed oil/water contact in the region of the well. The appropriate response to this is to reduce the overall flow rate in order to optimize the oil extraction rate. Typically this is achieved with a choke valve 134 located in or close to the wellhead 132. The choke value may be variable, but more commonly it consists of a fixed orifice of a precise flow section that under normal operating conditions, produces “critical flow”, a supersonic flow that is only dependent on the wellhead pressure upstream of the choke, independent of the pressure downstream of the choke. Selecting a specific size of choke enables the reservoir engineer to select an optimum flowrate for the well. Within a reasonably wide range, the well flowrate is then not affected by varying back pressure in the flowline 130 to the surface facility 126.
The surface facility separates the oil, water and gas streams and measures the flowrate of each phase, disposes of the water (and sometimes gas), and passes the other fluids to market. The surface facility typically receives the flow from many wells, and has a test separator and a production separator. Most of the wells are comingled and flow into the production separator, where only the aggregate flowrates are available, From time to time, the flow from each well is sent to the test separator, and then the phase flowrates for oil, gas and water for that well are measured. It will be clear that for most of the time, the well flows are not measured; instead flows are inferred from general measurements by a process known in the industry as “allocation”. Allocation is important as the reservoir and well production can only be optimized if the flow from each well is known. Also, in certain countries, royalty rates for each state are calculated on the basis of well production within the state boundaries, so a general production figure for an entire oil field that crosses state boundaries is not detailed enough, and individual well production figures are needed.
Individual separators for each well would be very costly, and so there is a need for a multiphase flowmeter (MPFM) that is cost effective for individual wells. A further advantage of installing MPFMs on each well is that rather than having individual flowlines running back to the surface facility, it is possible to comingle the flows of wells into a single larger flowline back to the facility. This approach has considerable cost advantages, particularly for subsea wells.
Attention has therefore been directed to in-line flowmeters able to distinguish between the three fractions. An example can be seen in U.S. Pat. No. 5,461,930 which discusses the measurement of two- and three-phase fluid flow. Volumetric and momentum (mass) flow meters are provided, which yield corresponding data from which (and from knowledge of the respective densities), the relative flow rates of the different phases can be determined.
Another example can be seen in US2004/0182172A1, which uses Venturis and chokes in the flowline to create pressure differentials along the flowline. The gas fraction is very much more compressible than the oil and water fractions, and therefore from assessing the pressure differentials produced by several different chokes and/or Venturis, it is possible (in principle) to determine the gas fraction. The relative water & oil fractions can then be determined by electrical properties of the fluid, particularly its capacitive properties in a manner that is acknowledged by US2004/0182172A1 as being known in the oil & gas industries.
This arrangement is proposed as an in-line meter 128 (FIG. 1) for use in the flowline 130 at some intermediate point between the production well and a remote processing location. However, as discussed in U.S. Pat. No. 5,461,930 in relation to still earlier designs, it suffers from the inherent difficulty that in order to create significant pressure differentials, there must be a significant flow restriction (by way of either a choke or a venturi). Thus, the flow of the fluid out of the well and to the remote processing location may be adversely affected. If the meter is designed so that there is little effect on flow, then the pressure differentials are correspondingly reduced and the accuracy of the meter is affected. Typically, such a device will have to measure pressure differentials of 1 or 2 bar in a base pressure of about 100 bar. To determine the proportions of the different fractions, three pressure differentials need to be compared, meaning that in order to obtain accurate information as to the fractional ratios, the pressure differentials will need to be accurate to millibar levels. This is a significant challenge.